1. Field of the Invention
The present invention pertains to processing gravity and magnetic data using vector and tensor data along with seismic data and more particularly to the inversion of gravity and magnetic data and combining with seismic data for hydrocarbon exploration and development, and to detect abnormally pressured subterranean formations in general, and with specific application to areas underneath and around anomalies such as salt, igneous or magmatic formations.
2. Related Prior Art
In exploration for hydrocarbons in subsurface environments containing anomalous density variations has always presented problems for traditional seismic imaging techniques by concealing geologic structures beneath zones of anomalous density. Many methods for delineating the extent of the highly anomalous density zones exist.
U.S. Pat. No. 4,987,561, titled xe2x80x9cSeismic Imaging of Steeply Dipping Geologic Interfaces, issued to David W. Bell, provides an excellent method for determining the side boundary of a highly anomalous density zone. This patent locates and identifies steeply dipping subsurfaces from seismic reflection data by first identifying select data which have characteristics indicating that seismic pulses have been reflected from both a substantially horizontal and a steeply dipping interface. These data are analyzed and processed to locate the steeply dipping interface. The processed data are displayed to illustrate the location and dip of the interface. This patent, while helping locate the boundaries, provides nothing to identify the subsurface formations on both sides of the boundary.
There have also been methods for identifying subsurface formations beneath anomalous zones using only seismic data to create a model and processing the data to identify formations in light of the model. By further processing reflection seismic data, the original model is modified or adjusted to more closely approximate reality.
An example of further processing seismic data to improve a model is U.S. Pat. No. 4,964,103, titled xe2x80x9cThree Dimensional Before Stack Depth Migration of Two Dimensional or Three Dimensional Data,xe2x80x9d issued to James H. Johnson. This patent provides a method of creating a three-dimensional model from two dimensional seismic data. This is done by providing a method of ray tracing to move before stack trace segments to their approximate three-dimensional position. The trace segments are scaled to depth, binned, stacked and compared to the seismic model. The model can then be changed to match the depth trace segments that will be stacked better, moved closer to their correct three-dimensional position and will compare better to the model. This patent uses a rather extensive seismic process to modify a seismic model that may be inaccurate.
One source of geologic exploration data that has not been used extensively in the past is potential fields data, such as gravity and magnetic data, both vector and tensor data and using potential fields data in combination with seismic data to provide a more accurate depth model or to derive a velocity model.
Gravity gradiometry has been in existence for many years although the more sophisticated versions have been held as military secret until recently. The measurement of gravity has become more acceptable in the late eighteen hundreds when measuring instruments with greater sensitivity were developed. Prior to this time, while gravity could be measured, variations in gravity caused by the effect of a large nearby object at one location, the gravity gradient, could not be reliably measured.
It has been known since the time of Sir Isaac Newton that bodies having mass exert a force on each other. The measurement of this force can identify large objects having a change in density even though the object is buried beneath the earth""s surface or in other ways out of sight.
Exploration for hydrocarbons in subsurface environments containing anomalous density variations such as salt formations, shale diapers and high pressure zones create havoc on seismic imaging techniques by concealing geologic structures beneath zones of anomalous density. By utilizing gravity, magnetic and tensor gravity field measurements along with a robust inversion process, these anomalous density zones can be modeled. The spatial resolution obtained from this process is normally much lower resolution than that obtained from reflection seismic data. However, models obtained from gravity and magnetic data can provide a more accurate starting model for the seismic processing. Using the potential fields data models as a starting point for two dimensional and three dimensional seismic depth imaging greatly enhances the probability of mapping these concealed geologic structures beneath the zones of anomalous density.
Zones of anomalous density may also be associated with zones of anomalous fluid pressure. Typically, while drilling an oil or gas well, the density of the drilling mud must be controlled so that its hydrostatic pressure is not less than the pore fluid pressure in any formation along the uncased borehole. Otherwise, formation fluid may flow into the wellbore, and cause a xe2x80x9ckick.xe2x80x9d Kicks can lead to blowouts if the flow is not stopped before the formation fluid reaches the top of the well. If the fluid contains hydrocarbons, there is a serious risk of an explosion triggered by a spark. For this reason, wellbores are drilled with a slight excess of the borehole fluid pressure over the formation fluid pressure.
A large excess of the borehole fluid pressure over the formation fluid pressure, on the other hand, is also undesirable. Fractures in the borehole wall may result in loss of circulation of the drilling fluid, resulting in stuck drill strings. Even if drilling can be continued, it is slowed down, resulting in greater costs. Serious formation damage may also occur.
Pressure prediction is done by estimating certain key parameters that include the overburden stress or confining stress, which is defined as the total lithostatic load on a rock volume at a given depth, and the effective stress, which is defined as the net load on the grain framework of the rock at a given depth. These two relations are then used in the Terzaghi effective stress law to estimate the fluid or pore pressure. Terzaghi""s law states that:
Pc=Pe+Pp
where:
(Pc)=the confining stress
(Pe)=the stresses born by the grains, and
(Pp)=the stress born by the fluid.
Some workers treat a special case of Terzaghi""s law where the confining stress is assumed to be the mean stress as opposed to the vertical confining stress. It should be acknowledged that this difference exists, but that it does not effect the embodiments of the present invention as they will pertain to estimating the total overburden load, which can then be converted to either vertical confining stress or mean stress based on the stress state assumptions that are made. The current prior art used for estimating confining stress is to use a density log from a nearby calibration well and integrate the density data to obtain the overburden load. This calibration was then applied from the mudline down to depths usually beyond the depth of sampling to predict the overburden away from the calibration well.
It has long been recognized that velocities of seismic waves through sedimentary formations are a function of xe2x80x9ceffective stress,xe2x80x9d defined as the difference between the stress caused by the overburden and the pore fluid pressure. A number of methods have been used to measure the seismic velocities through underground formations and make an estimate of the formation fluid pressure from the measured velocities. Plumley (1980) and U.S. Pat. No. 5,200,929 issued to Bowers, (the ""929 patent) describe a method for estimating the pore fluid pressure at a specified location. The method also accounts for possible hysteresis effects due to unloading of the rock formation. The method utilized a pair of sonic velocity-effective stress relations. One relationship is for formations in which the current effective stress is the highest ever experienced. A second relationship is used when the effective stress has been reduced from the maximum effective stress experienced by the rock and hysteresis must be accounted for.
The ""929 patent uses density data from nearby wells or from a geologically similar well to obtain the overburden stress. In most circumstances, the overburden stress may be adequately described by general compaction models in which the density increases with depth, giving rise to a corresponding relation for the relation between depth and overburden. In the absence of well control, determination of the overburden stress even within a sedimentary column is problematic. Furthermore, there are circumstances in which the model of a density that increases uniformly with depth is not valid. In such cases, the assumption of increasing density with depth is violated and a different approach to estimation of the overburden stress is needed.
There are several types of situations that may arise wherein a model of density increasing with depth and compaction is not valid. In the first case, there is a region of abnormally high density in the subsurface, usually of magmatic origin. The region could consist of an extrusive or intrusive volcanic material having relative density of 2.8 or higher. When such a formation is present within a sedimentary section where the relative density is typically between 2.4 and 2.65, the result is an increase in the overburden stress underneath the formation over what would be determined by prior art calculations. On the other hand, a region of abnormally low density may occur from salt bodies (2.10) or shale diapirs. In such a case, the overburden stress is abnormally low compared to what would be determined by prior art methods. In either case, even if the effective stress could be determined from seismic velocity measurements, a formation fluid pressure determination based on a prior art density model would be invalid.
In prior art, it is common to extrapolate away from a control well to derive an initial pressure model. When abnormally pressured sediments are present having higher porosity and lower density than sediments in the control well, the model of increasing density with depth is violated and the confining pressure is overestimated.
There is a need for a method to image subterranean formations which are responsive to potential fields and non-potential fields data. The present invention combines these data types to extract more useful information than either data type has provided before.
There is a need for a method for accurate determination of fluid pressures in the subsurface that (1) does not require the availability of density logs and (2) can more accurately determine the density of the subsurface in 2D or 3D away from and deeper than the limits of density from well control. Such a method should preferably be able to obtain fluid pressure even in the presence of anomalous formations that have densities significantly different from those expected in normal sedimentary columns or that predicted by density values in single or multiple wells. The present invention satisfies this need.
The present invention is a method for determining a parameter of interest of a region of interest of the earth. At least one component of potential fields data is measured at a plurality of locations over a region of interest including a subterranean formation of interest. The potential fields data are selected from magnetic data and gravity data. An initial geophysical model is determined for the region including the subterranean formation of interest. For the model, geophysical tensor data is updated using a forward model at a plurality of locations using an interior method for constrained optimization. A difference between the estimated model value and the measured value of the potential field measurements are determined at the plurality of locations. Based on the this difference the geophysical model is updated. The model is iteratively updated and compared to the measured data until the differences reach an acceptable level and the parameter of interest has been determined.
The present invention incorporates a robust inversion process for determining parameters and geologic structure representing subterranean formations using vector and tensor potential fields data, both gravity and magnetics. One or more components of potential fields vector and tensor data are measured at a plurality of locations over a region including the anomalous formation. The potential fields may be either gravity fields or magnetic fields, vector and/or tensor. A geophysical model of the region including the anomalous formation is determined using gravity, magnetics, seismic or a combination of these. A value of the one or more components of the potential fields vector and tensor data at the plurality of locations is estimated for the model. A difference between the estimated values and the measured values at the plurality of locations is determined. The model of the region is updated based on the difference. The estimate of the value of the one or more components, the determination of the difference and the updating of the model is repeated until the difference reaches a minimum value. The updated model is used to determine the parameter of interest. Abnormal densities in the subterranean formations are commonly associated with a salt body, a shale diapir, and extrusive or intrusive igneous bodies. In one embodiment the parameter of interest can be combined with seismic data representing the same parameter for depth imaging to provide a geologic depth model and to derive a velocity model. In another embodiment, seismic data can be introduced into the inversion process to further refine the lower boundary parameter predictions. The process of inversion followed by seismic imaging followed by another inversion and seismic imaging step is repeated until the results of the gravity magnetics inversion and the seismic imaging processes converge to a single answer. The seismically determined velocities give an estimate of the effective stress while the inverted density model gives the overburden stress. The difference between the overburden and the effective stress is the fluid pressure.